U.S. patent number 8,425,765 [Application Number 13/228,973] was granted by the patent office on 2013-04-23 for method of injecting solid organic acids into crude oil.
This patent grant is currently assigned to Baker Hughes Incorporated. The grantee listed for this patent is Lawrence N. Kremer, Corina Sandu, Jerry J. Weers. Invention is credited to Lawrence N. Kremer, Corina Sandu, Jerry J. Weers.
United States Patent |
8,425,765 |
Kremer , et al. |
April 23, 2013 |
**Please see images for:
( Certificate of Correction ) ** |
Method of injecting solid organic acids into crude oil
Abstract
Solid organic acids may be introduced into hydrocarbon solvents
to form dispersions; the dispersions in turn may be introduced into
crude oil. A wash water may be added to the crude oil to create an
emulsion. The organic acids may transfer metals and/or amines from
a hydrocarbon phase into an aqueous phase in an electrostatic
desalter which resolves the emulsion into the two phases. Suitable
solid organic acids include, but are not necessarily limited to,
C2-C4 alpha hydroxyacids, such as, but not necessarily limited to,
glycolic acid, malic acid, maleic acid, malonic acid, succinic acid
and even sulfamic acid, chloroacetic acid, thiomalic acid,
including esters of, polymers of, amine salts of, alkali metal
salts of, and/or ammonium salts of all of these acids.
Inventors: |
Kremer; Lawrence N. (The
Woodlands, TX), Weers; Jerry J. (Richmond, TX), Sandu;
Corina (Pearland, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Kremer; Lawrence N.
Weers; Jerry J.
Sandu; Corina |
The Woodlands
Richmond
Pearland |
TX
TX
TX |
US
US
US |
|
|
Assignee: |
Baker Hughes Incorporated
(Houston, TX)
|
Family
ID: |
47832826 |
Appl.
No.: |
13/228,973 |
Filed: |
September 9, 2011 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20120043256 A1 |
Feb 23, 2012 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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13008615 |
Jan 18, 2011 |
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12390631 |
Feb 23, 2009 |
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10649921 |
Mar 3, 2009 |
7497943 |
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60407139 |
Aug 30, 2002 |
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Current U.S.
Class: |
208/282;
208/254R; 208/252 |
Current CPC
Class: |
B01D
17/0217 (20130101); C10G 31/08 (20130101); B01D
17/047 (20130101); C10G 33/04 (20130101); C10G
17/04 (20130101); C10G 33/02 (20130101); B01D
17/0217 (20130101); B01D 17/047 (20130101); C10G
2300/44 (20130101); C10G 2300/1055 (20130101); C10G
2300/1096 (20130101); C10G 2300/1051 (20130101); C10G
2300/205 (20130101) |
Current International
Class: |
C10G
17/04 (20060101) |
Field of
Search: |
;208/251R,252,254R,282 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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SU |
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WO |
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WO |
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Other References
JH. Gary, et al., Petroleum Refining: Technology and Economics, 3rd
Edition, Chapter 4, Crude Distillation, 1994, pp. 39-69, Marcel
Dekker, Inc., New York. cited by applicant .
PCT International Search Report for International Application No.
PCT/US03/27116, Dec. 23, 2003. cited by applicant .
J. Weers, et al., "A New Metals Removal Process for Doba Crude
Oil," ERTC 9th Annual Meeting, Prague, Czech Republic, Nov. 15,
2004. cited by applicant .
J.J. Weers et al., "Calcium Removal from High TAN Crudes,"
Petroleum Technology Quarterly, Q3, 2005, avilalbe from
www.eptq.com. cited by applicant .
Baker Petrolite, "Remove Metals, Improve Margins," EXCALIBUR
brochure, 2005. cited by applicant.
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Primary Examiner: Griffin; Walter D
Assistant Examiner: Robinson; Renee E
Attorney, Agent or Firm: Mossman Kumar & Tyler PC
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATIONS
This application is a continuation-in-part application of U.S.
patent application Ser. No. 13/008,615 filed Jan. 18, 2011, which
in turn is a continuation application of U.S. patent application
Ser. No. 12/390,631 filed Feb. 23, 2009, which is a divisional
application of U.S. patent application Ser. No. 10/649,921 filed
Aug. 27, 2003, issued as U.S. Pat. No. 7,497,943 on Mar. 3, 2009,
which in turn claims the benefit of U.S. Provisional Application
No. 60/407,139 filed Aug. 30, 2002.
Claims
What is claimed is:
1. A method for introducing a solid acid into a hydrocarbon to be
treated comprising: dispersing a solid acid into a hydrocarbon
solvent to form a dispersion using high shear dispersion technology
selected from the group consisting of ultrasonic mixers,
disruptors, bead mills, homogenizers and combinations thereof,
where the solid acid is selected from the group consisting of
C.sub.2--C.sub.4 alpha-hydroxy acids, sulfamic acid, chloroacetic
acid, thiomalic acid, and esters of, polymers of, amine salts of,
alkali metal salts of, and ammonia salts of these acids, and
mixtures thereof, where the hydrocarbon solvent is different from
the hydrocarbon to be treated, where the dispersion further
comprises at least one dispersant selected from the group
consisting of carboxymethyl cellulose, xanthan gum,
polyvinylpyrrolidone, and mixtures thereof; and introducing the
dispersion into the hydrocarbon to be treated.
2. The method of claim 1 where the solid organic acid is at least
one C.sub.2--C.sub.4 alpha-hydroxy acid selected from the group
consisting of malic acid, lactic acid, glycolic acid, maleic acid,
malonic acid, succinic acid, tartaric acid, and thiomalic acid.
3. The method of claim 1 where: the hydrocarbon solvent is selected
from the group consisting of light cycle oil (LCO), kerosene,
aromatic solvents, paraffin oils, diesel oil, and mixtures thereof;
and the hydrocarbon to be treated is crude oil.
4. The method of claim 1 where the amount of solid acid in the
hydrocarbon solvent ranges from about 5 wt % to about 70 wt %.
5. The method of claim 1 where the solid acid is a powder having an
average particle size of about 5 microns or below.
6. A method of transferring metals and/or amines from a hydrocarbon
phase to a water phase in a process comprising: in any order:
adding a solid acid dispersion to a crude oil, where the solid acid
dispersion comprises a solid acid dispersed in a hydrocarbon
solvent to form a dispersion, where the solid acid is selected from
the group consisting of C.sub.2--C.sub.4 alpha-hydroxy acids,
sulfamic acid, chloroacetic acid, thiomalic acid, polymers of,
amine salts of, alkali metal salts of, and ammonia salts of these
acids, and mixtures thereof, where the hydrocarbon solvent is
different from the crude oil, where the dispersion further
comprises at least one dispersant selected from the group
consisting of carboxymethyl cellulose, xanthan gum,
polyvinylpyrrolidone, and mixtures thereof, where the solid acid
dispersion is made using high shear dispersion technology selected
from the group consisting of ultrasonic mixers, disruptors, bead
mills, homogenizers and combinations thereof, and adding wash water
to a crude oil to create an emulsion, where the crude oil comprises
metals and/or amines, where the solid acid is present in the
emulsion in an amount effective to transfer metals and/or amines
from a hydrocarbon phase to a water phase; and resolving the
emulsion into a hydrocarbon phase and an aqueous phase using
electrostatic coalescence, where at least a portion of the metals
and/or amines are transferred to the aqueous phase.
7. The method of claim 6 where in the solid acid dispersion, the
solid acid ranges from about 5 wt % to about 70 wt % of the
dispersion.
8. The method of claim 6 where the solid acid is present in the
emulsion in an amount ranging from about 1 to about 2000 ppm.
9. The method of claim 6 where the hydrocarbon solvent is selected
from the group consisting of light cycle oil (LCO), kerosene,
aromatic solvents, paraffin oils, diesel oil, crude oil, and
mixtures thereof.
10. A treated crude oil emulsion comprising: crude oil; a
dispersion comprising: a solid acid selected from the group
consisting of C.sub.2--C.sub.4 alpha-hydroxy acids, sulfamic acid,
chloroacetic acid, thiomalic acid, and esters of, polymers of,
amine salts of, alkali metal salts of, and ammonia salts of these
acids, and mixtures thereof, where the hydrocarbon solvent is
different from the crude oil; a hydrocarbon solvent; and at least
one dispersant selected from the group consisting of carboxymethyl
cellulose, xanthan gum, polyvinylpyrrolidone, and mixtures thereof,
where the dispersion is made using high shear dispersion technology
selected from the group consisting of ultrasonic mixers,
disruptors, bead mills, homogenizers and combinations thereof; and
wash water.
11. The treated crude oil emulsion of claim 10 where in the solid
acid dispersion, the solid acid ranges from about 5 wt % to about
70 wt % of the dispersion.
12. The treated crude oil emulsion of claim 10 where the solid acid
is present in the treated crude oil emulsion in an amount ranging
from about 1 to about 2000 ppm.
13. The treated crude oil emulsion of claim 10 where the solid
organic acid is at least one C.sub.2--C.sub.4 alpha-hydroxy acid
selected from the group consisting of malic acid, lactic acid,
glycolic acid, maleic acid, malonic acid, succinic acid, tartaric
acid, and thiomalic acid.
14. The treated crude oil emulsion of claim 10 where the
hydrocarbon solvent is selected from the group consisting of light
cycle oil, kerosene, aromatic solvents, paraffin oils, diesel oil,
and mixtures thereof.
15. The treated crude oil emulsion of claim 10 where the amount of
solid acid in the hydrocarbon solvent ranges from about 5 wt % to
about 70 wt %.
Description
TECHNICAL FIELD
The present invention relates to methods and compositions for
introducing solid acids into a hydrocarbon, and more particularly
relates, in one non-limiting embodiment, to methods and
compositions for introducing solid acids, such as C.sub.2--C.sub.4
hydroxyacids, into a hydrocarbon, such as crude oil, where
subsequently metals and/or amines are transferred to an aqueous
phase in an emulsion breaking process.
BACKGROUND
In an oil refinery, the desalting of crude oil has been practiced
for many years. The crude is usually contaminated from several
sources, including, but not necessarily limited to: Brine
contamination in the crude oil as a result of the brine associated
with the oil in the ground; Minerals, clay, silt, and sand from the
formation around the oil well bore; Metals including calcium, zinc,
silicon, nickel, sodium, potassium, etc.; Nitrogen-containing
compounds such as amines used to scrub H.sub.2S from refinery gas
streams in amine units, or from amines used as neutralizers in
crude unit overhead systems, and also from H.sub.2S scavengers used
in the oilfield; and Iron sulfides and iron oxides resulting from
pipeline and vessel corrosion during production, transport, and
storage.
Desalting is necessary prior to further processing to remove these
salts and other inorganic materials that would otherwise cause
fouling and deposits in downstream heat exchanger equipment and/or
form corrosive salts detrimental to crude oil processing equipment.
Further, these metals can act as poisons for the catalysts used in
downstream refinery units. Effective crude oil desalting can help
minimize the effects of these contaminants on the crude unit and
downstream operations. Proper desalter operations provide the
following benefits to the refiner: Reduced crude unit corrosion.
Reduced crude preheat system fouling. Reduced potential for
distillation column damage. Reduced energy costs. Reduced
downstream process and product contamination.
Desalting is the resolution of the natural emulsion of water that
accompanies the crude oil by creating another emulsion in which
about 2 to about 10 wt % percent relative wash water is dispersed
into the oil using a mix valve. For relatively lighter crudes, the
wash water proportion may range from about 3 to about 5 wt %; for
relatively heavier (lower gravity) crudes, the wash water
proportion may range from about 5 to about 8 wt %. The emulsion mix
is directed into a desalter vessel containing a parallel series of
electrically charged plates. Under this arrangement, the oil and
water emulsion is exposed to the applied electrical field. An
induced dipole is formed on each water droplet within the emulsion
that causes electrostatic attraction and coalescence of the water
droplets into larger and larger droplets. Eventually, the emulsion
resolves into two separate phases--the oil phase (top layer) and
the water phase (bottom layer). The streams of desalted crude oil
and effluent water are separately discharged from the desalter.
The entire desalting process is a continuous flow procedure as
opposed to a batch process. Normally, chemical additives are
injected before the mix valve to help resolve the oil/water
emulsion in addition to the use of electrostatic coalescence,
although some additives or portions of additives may be injected
elsewhere. These additives effectively allow small water droplets
to more easily coalesce by lowering the oil/water interfacial
tension.
Crude oil that contains a high percent of particulate solids can
complicate the desalting process. The particulate solids, by
nature, would prefer to transfer to the water phase. However, much
of the solids in a crude oil from a field exist in tight
water-in-oil emulsions. That is, oil-wetted solids in high
concentration in the crude may help form tight oil and water
emulsions that are difficult to resolve. These tight emulsions are
often referred to as "rag" and may exist as a layer between the
separated oil and water phases. The rag layer inside the desalter
vessel may grow to such an extent that some of it will be
inadvertently discharged with the water phase. This is a problem
for the waste water treatment plant since the rag layer still
contains a high percentage of unresolved emulsified oil.
As mentioned, much of the solids encountered during crude oil
desalting consists of iron, most commonly as particulate iron such
as iron oxide, iron sulfide, etc. Other metals that are desirably
removed include, but are not necessarily limited to, calcium, zinc,
silicon, nickel, sodium, potassium, and the like, and typically a
number of these metals are present. Some of the metals may be
present in a soluble form. The metals may be present in inorganic
or organic forms. In addition to complicating the desalter
operation, iron and other metals are of particular concern to
further downstream processing. This includes the coking operation
since iron and other metals remaining in the processed hydrocarbon
yields a lower grade of coke. Removing the metals from the crude
oil early in the hydrocarbon processing stages is desired to
eventually yield high quality coke as well as to limit corrosion
and fouling processing problems.
Several treatment approaches have been made to reduce total metal
levels and these all center on the removal of metals at the
desalter unit. Normally, the desalter only removes water soluble
inorganic salts such as sodium or potassium chlorides. Some crude
oils contain water insoluble metal organic acid salts such as
calcium naphthenante and iron naphthenate, which are soluble or
dispersed as fine particulate matter in the oil but not in
water.
U.S. Pat. No. 7,497,943 concerns the discovery that metals and/or
amines may be removed or transferred from a hydrocarbon phase to a
water phase in an emulsion breaking process by using a composition
that contains water-soluble hydroxyacids. Suitable water-soluble
hydroxyacids include, but are not necessarily limited to glycolic
acid, gluconic acid, C.sub.2--C.sub.4 alpha-hydroxy acids,
poly-hydroxy carboxylic acids, thioglycolic acid, chloroacetic
acid, polymeric forms of the above hydroxyacids, poly-glycolic
esters, glycolate ethers, and ammonium salt and alkali metal salts
of these hydroxyacids, and mixtures thereof. The composition may
also optionally include at least one mineral acid to reduce the pH
of the desalter wash water. The method permits transfer of metals
and/or amines into the aqueous phase with little or no hydrocarbon
phase undercarry into the aqueous phase. The composition is
particularly useful in treating crude oil emulsions, and in
removing calcium and other metals therefrom.
However, typically in the '943 method the water-soluble
hydroxyacids are dissolved in water and injected into the desalter
wash water. These water-based products are subject to freezing in
cold weather environments. In addition, sometimes these water-based
products are unstable, that is the hydroxyacids may settle out over
time.
It would thus be desirable to develop compositions and methods for
introducing solid acids, such as solid organic acids or solid
alpha-hydroxyacids into a hydrocarbon to be treated, such as crude
oil, by using a composition that is stable and not as susceptible
to freezing in cold environments.
SUMMARY
In one non-restrictive version, there is provided a method for
introducing a solid acid into a hydrocarbon to be treated, where
the method includes dispersing a solid acid into a hydrocarbon
solvent to form a dispersion. The solid acid may include, but is
not necessarily limited to, C.sub.2--C.sub.4 alpha-hydroxy acids,
sulfamic acid, chloroacetic acid, thiomalic acid, and esters of,
polymers of, amine salts of, alkali metal salts of, and ammonia
salts of these acids, and mixtures thereof. The hydrocarbon solvent
is different from the hydrocarbon to be treated. The method further
involves introducing the dispersion into the hydrocarbon to be
subsequently treated, e.g. a crude oil, for instance to transfer
metals and/or amines from a hydrocarbon phase to an aqueous phase
in a desalter.
Further in another non-limiting version there is provided a method
of transferring metals and/or amines from a hydrocarbon phase to a
water phase in a process. The method involves, in any order, adding
a solid acid dispersion to a crude oil and adding wash water to a
crude oil to create an emulsion, where the crude oil comprises
metals and/or amines. The solid acid dispersion comprises a solid
acid dispersed in a hydrocarbon solvent to form a dispersion, where
the solid acid includes, but is not necessarily limited to,
C.sub.2--C.sub.4 alpha-hydroxy acids, sulfamic acid, chloroacetic
acid, thiomalic acid, and esters of, polymers of, amine salts of,
alkali metal salts of, and ammonia salts of these acids, and
mixtures thereof. The hydrocarbon solvent is different from the
crude oil. The solid acid is present in the emulsion in an amount
effective to transfer metals and/or amines from a hydrocarbon phase
to a water phase. The method further involves resolving the
emulsion into a hydrocarbon phase and an aqueous phase using
electrostatic coalescence, where at least a portion of the metals
and/or amines are transferred to the aqueous phase.
In another non-limiting embodiment there is provided a stable
dispersion that includes a hydrocarbon solvent and a solid acid.
Again, the solid acid includes, but is not necessarily limited to,
C.sub.2--C.sub.4 alpha-hydroxy acids, sulfamic acid, chloroacetic
acid, thiomalic acid, and esters of, polymers of, amine salts of,
alkali metal salts of, and ammonia salts of these acids, and
mixtures thereof.
There is provided in different non-restrictive embodiment a treated
crude oil emulsion that includes crude oil, wash water and a
dispersion. The dispersion involves a hydrocarbon solvent and a
solid acid that includes, but is not necessarily limited to,
C.sub.2C.sub.4 alpha-hydroxy acids, sulfamic acid, chloroacetic
acid, thiomalic acid, and esters of, polymers of, amine salts of,
alkali metal salts of, and ammonia salts of these acids, and
mixtures thereof. The hydrocarbon solvent is different from the
crude oil.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1A is an optical microphotograph of an unprocessed dispersion
of 5 wt % solid malic acid in mineral oil;
FIG. 1B is an optical microphotograph of the dispersion of FIG. 1A
after one pass in the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM.
Processor at 30,000 psi (207 MPa);
FIG. 2A is a photograph of three bottles of 5 wt % solid malic acid
in mineral oil, left to right: unprocessed, after one pass in the
H30Z-G10Z chamber of a MICROFLUIDIZER.RTM. Processor at 30,000 psi
(207 MPa), and after two passes in the H30Z-G10Z chamber of a
MICROFLUIDIZER.RTM. Processor at 30,000 psi (207 MPa), all after
one minute;
FIG. 2B is a photograph of the three bottles of FIG. 2A after four
hours;
FIG. 3A is an optical microphotograph of an unprocessed dispersion
of 5 wt % solid malic acid in Heavy Aromatic Solvent 100;
FIG. 3B is an optical microphotograph of the dispersion of FIG. 3A
after one pass in the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM.
Processor at 30,000 psi (207 MPa);
FIG. 3C is an optical microphotograph of the dispersion of FIG. 3A
after two passes in the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM.
Processor at 30,000 psi (207 MPa);
FIG. 4A is a photograph of three bottles of 5 wt % solid malic acid
in Heavy Aromatic Solvent 100, left to right: unprocessed, after
one pass in the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM.
Processor at 30,000 psi (207 MPa), and after two passes in the
H30Z-G10Z chamber of a MICROFLUIDIZER.RTM. Processor at 30,000 psi
(207 MPa), all after one minute; and
FIG. 4B is a photograph of the three bottles of FIG. 4A after four
hours.
DETAILED DESCRIPTION
The inventors have discovered that solid acids, for instance
powdered solid acids or solid acids having a size in the range of
nanometers or larger may be dispersed in a hydrocarbon solvent. It
is desirable to disperse organic acids such as glycolic acid or
malic acid (as non-limiting examples) into an oil rather than into
water. Water-based products are prone to freezing and being
unstable, that is, the solid acids may precipitate out and/or
settle over time. Further, since the contaminants to be removed
from a hydrocarbon to be treated, such as a crude oil, are
initially in the crude oil, the introduction of the solid acids in
a hydrocarbon solvent and subsequently into the crude oil
facilitates contact of the solid acids with the impurities to be
removed. By adding the acids as an oil-based product, they may
react faster and/or more efficiently, with the contaminants.
More specifically, powdered acids, such as malic acid or even
sulfamic acid, may be dispersed in hydrocarbons, such as kerosene
or light cycle oil (LCO). In some cases, it may be necessary to use
high shear dispersion technology, such as ultrasonic disruptors and
ultrasonic mixers or bead mills. To prevent the dispersed particles
from settling, it may be necessary in some non-limiting embodiments
to also add a dispersant. Suitable dispersants include, but are not
necessarily limited to, carboxymethyl cellulose (CMC), xanthan gum,
and polyvinylpyrrolidone (PVP) and combinations thereof. It is
possible that in some non-restrictive versions, if the acid is
sufficiently small, for instance of nano-scale size, special high
shear dispersion technology may not be necessary, and conventional
mixing processes may be used, including, but not necessarily
limited to, conventional paddle mixing in a tank, a static mixer,
and combinations thereof.
The compositions and methods herein involve an alternative way to
deliver some of the same acids used in previous techniques where
the acids are introduced into wash water, such as those described
in U.S. Pat. No. 7,497,943, from which this application claims
priority, incorporated herein by reference in its entirety. The
water-free additive may be injected into a hydrocarbon to be
treated, such as crude oil, without the need for any water, such as
wash water, to be present at that point.
It was previously discovered that the addition of glycolic acid
(hydroxyacetic acid) and other water-soluble hydroxyacids to a
crude oil can significantly reduce the amount of calcium, iron and
other metals and/or amines in the hydrocarbon when it is run
through a desalter in a refinery. A comparison of the "normal"
desalting process on a reference crude oil containing higher than
normal amounts of calcium found minimal calcium removal. In
contrast, the addition of glycolic acid in levels of up to a 5:1
ratio with calcium, results in much lower metals and/or amine
content of the desalted oil. The levels of metals other than
calcium such as iron, zinc, silicon, nickel, sodium and potassium
were also reduced. The removal of particulate iron in the form of
iron oxide, iron sulfide, etc. is a specific, non-limiting
embodiment of the method. By "removing" the metals and/or amines
from the hydrocarbon or crude is meant any and all partitioning,
sequestering, separating, transferring, eliminating, dividing,
removing, of one or more metal or amine from the hydrocarbon or
crude to any extent, into a water phase.
In one embodiment, the useful acids include a water-soluble hydroxy
acid. Hydroxy acids are defined herein as not including or
exclusive of acetic acid. Acetic acid has sometimes been used to
remove metals as well, but it has a high oil solubility and tends
to stay with the hydrocarbon coming from the desalter. The acidity
of the acetic acid can then cause corrosion problems in the crude
unit. Most of the hydroxy acids will not partition as much into the
crude oil, thus reducing downstream concerns. They are also less
volatile and do not distill into the crude unit overhead system
where they can increase corrosion rates when combined with the
water usually present at this location.
In one preferred, non-limiting embodiment, the hydroxyacid is
selected from the group consisting of glycolic acid,
C.sub.1--C.sub.4 alpha-hydroxy acids, poly-hydroxy carboxylic
acids, thioglycolic acid, chloroacetic acid (melting
point=63.degree. C.), polymeric forms of the above hydroxyacids,
glycolate ethers, poly-glycolic esters, and mixtures thereof. While
thioglycolic acid and chloroacetic acid are not strictly speaking
hydroxyacids, they are functional equivalents thereof. For the
purposes herein, they are defined as hydroxyacids. The alpha
substituent on the C.sub.1--C.sub.4 alpha-hydroxy acids may be any
C.sub.1--C.sub.4 straight or branched alkyl group. In one
non-limiting embodiment, the alpha substituent may be
C.sub.2--C.sub.4 straight or branched alkyl group. Lactic acid
(m.p.=53.degree. C.) is optionally not included in this group.
Gluconic acid, CH.sub.2OH(CHOH).sub.4COOH, (m.p.=131.degree. C.) is
a non-limiting but preferred polymer of glycolic acid. The
glycolate ethers may have the formula:
##STR00001## where n ranges from 1-10. The glycolate esters may
have a formula:
##STR00002## where n is as above. Thioglycolic acid and the ethers
of glycolic acid may have the added benefits of a higher boiling
point, and possibly increased water solubility. A higher boiling
point means the additive will not distill into the distillate
fractions in the crude unit and cause corrosion or product quality
concerns. The higher water solubility also favors removal of the
additive from the crude in the desalter and reduces the amount that
may reach the downstream processing units.
In particular, the definition of the solid acids encompasses herein
and water-soluble hydroxyacids in particular includes ammonium
salts thereof and alkali metal salts thereof (e.g. sodium and
potassium salts, etc.) of these hydroxyacids alone or in
combination with the other water-soluble hydroxyacids mentioned.
Such salts would be formed in the desalter wash water as the
system's pH was adjusted with basic pH adjusters such as sodium
hydroxide, potassium hydroxide, ammonia, and the like.
In another non-limiting embodiment the water-soluble hydroxyacids
do not include citric acid (m.p.=153.degree. C.), malic acid
(m.p.=101.degree. C.), tartaric acid (m.p. =171-174.degree. C.;
L-tartaric), mandelic acid (m.p.=119.degree. C.), and lactic acid
(m.p.=53.degree. C.). However, in different embodiments, one or
more of these acids may be usefully included (unless otherwise
noted, they should be considered as included). In yet another
non-limiting embodiment, the definition of water-soluble
hydroxyacids does not include organic acid anhydrides, particularly
acetic, propionic, butyric, valeric, stearic, phthalic and benzoic
anhydrides.
In yet another non-limiting embodiment, glycolic acid
(m.p.=80.degree. C.) and gluconic acid may be used to remove
calcium and amines, and thioglycolic acid may be used for iron
removal, from crude oil or another hydrocarbon phase.
In one non-limiting embodiment, the solid acids are a powder,
defined herein as a dry, bulk solid composed of a large number of
very fine particles that may flow freely when shaken or tilted. In
one non-restrictive version, the average particle size of a powder
is about 5 microns or less, alternatively about 0.5 microns or
less, and in another non-limiting embodiment is about 0.1 microns
or less.
In general, the smaller the average particle size of the solid
acids, the more easily they are dispersed, and in turn, the more
easily they contact and react with the metal contaminants and
amines of the hydrocarbon which are to be removed therefrom. For
these even smaller sizes, the average particle size is about 75 nm
or smaller, alternatively, about 50 nm or smaller, and in another
non-limiting embodiment about 25 nm or smaller. For the solid acids
in this range, they may be incorporated into the hydrocarbon
solvent using conventional mixing techniques.
The hydrocarbons into which the solid acids may be dispersed
include, but are not necessarily limited to, light cycle oil (LCO),
kerosene, aromatic solvents, paraffin oils, diesel oil, crude oil,
and mixtures thereof. The hydrocarbon used should be one into which
the solid acid is compatible to be dispersed, but which is
compatible with the hydrocarbon into which the dispersion is to be
introduced, most typically crude oil. In another non-limiting
embodiment, it would be suitable to introduce the solid acid
particles into a slip stream of crude oil; the crude oil may have
enough viscosity to hold the particles in suspension.
The introduction of the solid acids, for instance, solid
C.sub.2--C.sub.4 alpha-hydroxy acids, may be accomplished by using
conventional techniques, for instance, but not necessarily limited
to, a tank or vessel having a paddle stirrer, a static mixer, a
ribbon blender, an industrial high shear mixer or granulator, and
the like. It may be necessary to special high shear dispersion
technology, including, but not necessarily limited to, ultrasonic
mixers or disruptors or bead mills or homogenizers.
In one non-limiting embodiment the amount of solid acid in the
hydrocarbon solvent may range from about 5 wt % independently up to
about 70 wt % (grams acid/grams hydrocarbon), alternatively from
about 20 wt % independently up to about 50 wt %. As used herein,
the term "independently" means that any lower threshold may be
combined with any upper threshold for the same parameter to give a
valid alternative range.
The resulting dispersion is then introduced into a hydrocarbon to
be subsequently treated, for instance crude oil to be desalted. The
desalting method will be valuable to produce high quality (i.e.,
high purity) coke from crude that may originally have contained
high concentrations of metals and/or amines and solids, including
iron-based solids. Further, such method advances the technology by
removing inorganic material from the crude oil while discharging
little or no oil or emulsion to the waste treatment plant.
It will be understood that the metals removed in the desalting
include, but are not necessarily limited to, those of Groups IA,
IIA, VB, VIII, IIB and IVA of the Periodic Table (CAS version). In
another non-limiting embodiment, the metals include, but are not
necessarily limited to calcium, iron, zinc, silicon, nickel,
sodium, potassium, vanadium, and combinations thereof. In
particular, nickel and vanadium are known poisons for catalysts
used in fluid catalytic cracking units (FCCUs) downstream.
The amines removed in accordance with the desalting method may
include, but are not necessarily limited to, monoethanolamine
(MEA); diethanolamine (DEA); triethanolamine (TEA);
N-methylethanolamine; N,N-dimethylethanolamine (DMEA); morpholine;
N-methyl morpholine; ethylenediamine (EDA); methoxypropylamine
(MOPA); N-ethyl morpholine (EMO); N-methyl ethanolamine,
N-methyldiethanolamine and combinations thereof.
It is expected that the acids, in particular hydroxyacids in a
non-limiting embodiment, will be used together with other additives
including, but not necessarily limited to, corrosion inhibitors,
demulsifiers, pH adjusters, metal chelants, scale inhibitors,
hydrocarbon solvents, and mixtures thereof, in a commercial
process. Metal chelants are compounds that complex with metals to
form chelates. It is not believed that the acids, e.g.
alpha-hydroxy acids, act as chelates in the removal of metals and
amines from the hydrocarbon phase to the aqueous phase. In
particular, mineral acids may be used since in some non-limiting
embodiments metal removal may be accomplished at an acidic pH. The
mineral acids may also be solids and may also be introduced into a
hydrocarbon solvent to form a dispersion as described herein. The
use of combinations of hydroxyacids, particularly glycolic acid or
gluconic acid, and mineral acids may give the best economics in a
commercial application. Suitable mineral acids for use in
conjunction with the water-soluble hydroxyacids include, but are
not necessarily limited to, sulfuric acid, hydrochloric acid,
phosphoric acid, nitric acid, phosphorous acid, and mixtures
thereof. As noted, in one non-restrictive embodiment, the method is
practiced in a refinery desalting process that involves washing the
crude emulsion with wash water. In one non-limiting embodiment, the
amount of mineral acid used may be sufficient to lower the pH of
the wash water to 6 or below. As noted below, in some
non-restrictive embodiments, it may be necessary or preferred to
lower the pH of the wash water to 5 or below, alternatively to 4 or
below. However, in a different, non-restrictive embodiment, the
wash water need not be acidic, and in some non-limiting embodiments
may be alkaline. In cases where the wash water pH is greater than
8, a benefit of the methods and compositions herein would be that
the pH of the resulting brine would be lowered by the solid acid
treatment. This procedure would be an alternative method of
lowering the brine water pH in cases where direct treating may not
be possible. The water-soluble hydroxyacids (and salts thereof) are
expected to be useful over a wide pH range, although in some
situations it may be necessary or desirable to adjust the pH to
achieve the desired contaminant transfer or separation.
It will be appreciated that the necessary, effective or desired
proportions of the hydroxyacid and/or the mineral acid will be
difficult to predict in advance, since these proportions or dosages
are dependent upon a number of factors, including, but not
necessarily limited to, the nature of the hydrocarbon, the
concentration of metal species and amine to be removed, the
temperature and pressure conditions of method, the particular
hydroxyacid and mineral acid used, etc. In general, the more of a
species, such as calcium, there is to be removed, the more of the
reactive acid that must be added. Since many undesirable species
are affected, a successful metal removal process may require more
reactive acid on a stoichiometric basis than would be indicated by
the concentration of only the target species. It may therefore be
insufficient to only just add enough acid to get the pH below 6.
Nevertheless, in order to give some sense of the proportions that
may be used, in one non-limiting embodiment, the composition may
comprise down to about 1 wt. % water-soluble hydroxyacid; and up to
about 20 wt. % mineral acid, preferably from about 1 independently
to about 100 wt. % water-soluble hydroxyacid; and from about 1
independently to about 20 wt. % mineral acid, and most preferably
from about 25 independently to about 85 wt. % water-soluble
hydroxyacid; and from about 15 independently to about 75 wt. %
mineral acid. In some non-limiting embodiments, the mineral acid is
optional and may be omitted.
The concentration of the dispersion to be used in the crude oil to
be effective is very difficult to predict in advance since it
depends on multiple, interrelated factors including, but not
limited to, the composition of the crude, the desalting conditions
(temperature, pressure, etc.), the flow rate of the crude and its
residence time in the desalter, among others. Nevertheless, for the
purposes of non-limiting illustration, the proportion of the active
acid or hydroxyacid that may be used in the crude (not including
any solvent or mineral acid) may range from about 1 independently
to about 2000 ppm-w, more preferably from about 10 independently to
about 500 ppm-w and will depend on the concentration of metal
species to be removed. The organic hydroxy acid reacts
stoichiometrically with the organo metal and/or amine species to be
removed. Thus an equivalent amount of organic hydroxy acid must be
added compared to the concentration of metal species to be removed.
A slight excess of the acid will ensure that the reaction goes to
completion. In one non-limiting embodiment, the amount of
water-soluble hydroxyacid is stoichiometric with the amount of
metals and/or amines present, or greater than stoichiometric. For
economic reasons the refinery may chose to leave some of the metal
and/or amine species in the crude at an acceptably low level of
contamination of hydrocarbon. In those cases the treatment level of
the hydroxy acids can be correspondingly reduced.
It is desirable that in the practice of method that there be no oil
carryunder in the aqueous phase, and that at least oil carryunder
is minimized. Further, while it is useful that all of the metals
and/or amines transfer to the aqueous phase, in one non-limiting
theory, some of the metals and/or amines may be transferred from
the oil phase into the rag. This proportion of metals and/or amines
is then removed when the rag is cleaned out.
It is also acceptable that in the practice of the method that all
of the metals and/or amines transfer to the aqueous phase. In
another non-limiting embodiment, 25% or less metal and/or amine is
present in the hydrocarbon phase after desalting, preferably 20% or
less metal and/or amine remains, most preferably only 10% or less
remains. In some cases the refinery may chose to leave higher
percentages of metal and/or amine contaminants in the crude if the
detrimental effects are judged to be economically acceptable.
The invention will be illustrated further with reference to the
following Examples, which are not intended to limit the invention,
but instead illuminate it further.
Preparation Examples 1 and 2
Solid malic acid was processed into the indicated hydrocarbon
solvent using a MICROFLUIDIZER.RTM. Processor at the indicated
pressure and number of passes of Table I.
TABLE-US-00001 TABLE I Malic Acid Samples Information Processor
Pressure, Ex. Sample Chamber psi (MPa) Pass Comments 1 5 wt % malic
H30Z-G10Z 30,000 1 The size of the acid in (207) 2 malic acid
mineral oil 5 particles appeared to be reduced after processing 2 5
wt % malic H30Z-G10Z 30,000 1 The particle size acid in Heavy (207)
2 reduction was Aromatic similar in both Solvent 100 hydrocarbon
solvents
Shown in FIG. 1A is an optical microphotograph of an unprocessed
dispersion of 5 wt % solid malic acid in mineral oil, while FIG. 1B
is an optical microphotograph of the dispersion of FIG. 1A after
one pass in the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM.
Processor at 30,000 psi (207 MPa). It may be seen that the
particles have been processed to be a smaller size. FIG. 2A is a
photograph of three bottles of 5 wt % solid malic acid in mineral
oil. The bottle on the left contains an unprocessed dispersion
while the bottle in the middle contains the dispersion after one
pass in the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM. Processor at
30,000 psi (207 MPa). The bottle on the right is the dispersion
after two passes in the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM.
Processor at 30,000 psi (207 MPa). FIG. 2A shows the appearance of
the three dispersions after settling for one minute. FIG. 2B is a
photograph of the three bottles of FIG. 2A after settling for four
hours, demonstrating more settling for the dispersion that was
processed in two passes than for the dispersion that was processed
in one pass.
FIG. 3A is an optical microphotograph of an unprocessed dispersion
of 5 wt % solid malic acid in Heavy Aromatic Solvent 100, where
FIG. 3B is an optical microphotograph of the dispersion of FIG. 3A
after one pass in the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM.
Processor at 30,000 psi (207 MPa). FIG. 3C is an optical
microphotograph of the dispersion of FIG. 3A after two passes in
the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM. Processor at 30,000
psi (207 MPa). It may be seen that the particle sizes become
smaller with each pass. FIG. 4A is a photograph of three bottles of
5 wt % solid malic acid in Heavy Aromatic Solvent 100. The bottle
on the left contains an unprocessed dispersion while the bottle in
the middle contains the dispersion after one pass in the H30Z-G10Z
chamber of a MICROFLUIDIZER.RTM. Processor at 30,000 psi (207 MPa).
The bottle on the right shows the dispersion after two passes in
the H30Z-G10Z chamber of a MICROFLUIDIZER.RTM. Processor at 30,000
psi (207 MPa). FIG. 4A shows the appearance of these three
dispersions after settling for one minute. FIG. 4B is a photograph
of the three bottles of FIG. 4A after settling for four hours,
demonstrating settling for both of the dispersions that were
processed in one and two passes.
Calcium Removal Examples 3-5
The sample testing preparation involved the following: Adding 0.34
wt % of the malic aid dispersion (either in mineral oil or Heavy
Aromatic Solvent 100, Examples 1 and 2, respectively) to crude oil.
Adding 5 wt % deionized (DI) water. Perform EDDA testing (the EDDA
Test Method described in U.S. Pat. No. 7,497,943 incorporated
herein by reference in its entirety was used). ICP analysis
(Inductively Coupled Plasma) on water samples was performed. ICP
analysis digestion on the crude side was employed. The results are
presented in Table II.
TABLE-US-00002 TABLE II Calcium Removal using Malic Acid in Heavy
Aromatic Solvent 100 4 5 3 Processed - Processed - Example
Unprocessed 1 Pass 2 Passes Water 238 870 722 Oil 75 35 40 Total
313 905 762
It may be seen that more calcium is extracted in the water due to
treatment with the new formulated product. More calcium is removal
from the oil is achieved via treatment with the new product.
In the foregoing specification, the invention has been described
with reference to specific embodiments thereof, and has been
demonstrated as effective in introducing solid acids, for instance
alpha-hydroxy acids into a hydrocarbon solvent to form a
dispersion, to be added to a hydrocarbon to be subsequently
processed, such as crude oil, as non-limiting examples. However, it
will be evident that various modifications and changes may be made
thereto without departing from the broader spirit or scope of the
invention as set forth in the appended claims. Accordingly, the
specification is to be regarded in an illustrative rather than a
restrictive sense. For example, specific solid acids, solid
hydroxyacids, and combinations thereof with other hydrocarbon
solvents, other than those specifically exemplified or mentioned,
or in different proportions, falling within the claimed parameters,
but not specifically identified or tried in a particular
application are within the scope herein. Similarly, it is expected
that the inventive compositions will find utility as metal transfer
compositions for other fluids besides crude oil emulsions.
The words "comprising" and "comprises" as used throughout the
claims is interpreted "including but not limited to".
The present invention may suitably comprise, consist or consist
essentially of the elements disclosed and may be practiced in the
absence of an element not disclosed. For instance, the method for
introducing a solid acid into a hydrocarbon to be treated may
consist of or consist essentially of dispersing a solid acid into a
hydrocarbon solvent to form a dispersion, and then introducing the
dispersion into the hydrocarbon to be treated, where the solid acid
is as defined in the claims. Additionally, the stable dispersion
may consist of or consist essentially of a solid acid selected from
the group consisting of C.sub.2--C.sub.4 alpha-hydroxy acids,
sulfamic acid, chloroacetic acid, thiomalic acid, and esters of,
polymers of, amine salts of, alkali metal salts of, and ammonia
salts of these acids, and mixtures thereof; and a hydrocarbon
solvent, where the hydrocarbon solvent is different from the
hydrocarbon to be treated. In another non-limiting embodiment, the
treated crude oil emulsion may consist of or consist essentially of
crude oil, wash water, and solid acid selected from the group
consisting of C.sub.2--C.sub.4 alpha-hydroxy acids, sulfamic acid,
chloroacetic acid, thiomalic acid, and esters of, polymers of,
amine salts of, alkali metal salts of, and ammonia salts of these
acids, and mixtures thereof, where the hydrocarbon solvent is
different from the crude oil.
* * * * *
References